Methods and electrically-actuated apparatus for wellbore operations

ABSTRACT

Embodiments of a bottomhole assembly BHA for completion of a wellbore are deployed on electrically-enabled coiled tubing (CT) and permit components of the BHA to be independently electrically actuated from surface for completion of multiple zones in a single trip using a single BHA having at least two electrically-actuated variable diameter packers. One or both of the packers may be actuated to expand or retract for opening and closing off a variety of flowpaths between the BHA and the wellbore, in new wellbores, old wellbores, cased wellbores, wellbores with sleeves and in openhole wellbores. Additional components in the BHA, which may also be electrically-actuated or powered, permit perforating, locating of the BHA in the wellbore such as using casing collar locators and microseismic monitoring in real time or in memory mode.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application61/639,493, filed Apr. 27, 2012, U.S. Provisional Application61/642,301, filed May 3, 2012, U.S. Provisional Application 61/658,277,filed Jun. 11, 2012 and U.S. Provisional Application 61/774,486, filedMar. 7, 2013, the entirety of which are incorporated fully herein byreference.

FIELD

Embodiments of the disclosure relate to methods and apparatus used forcompletion of a wellbore and, more particularly, to methods utilizingelectrically-actuated apparatus for performing completion operations andoptionally, simultaneous microseismic monitoring thereof.

BACKGROUND

Apparatus and methods are known for single-trip completions of deviatedwellbores, such as horizontal wellbores. To date, unlike the drillingindustry which commonly utilizes intelligent apparatus for drillingwellbores, particularly horizontal or deviated wellbores, the fracturingindustry has relied largely on mechanically-actuated apparatus toperform at least a majority of the operations required to complete awellbore. This is particularly the case with coiled-tubing deployedbottom hole assemblies (BHA's), largely due to the difficulty inproviding sufficient, reliable electrical signals and power from surfaceto the BHA and from the BHA to surface.

It is known to deploy BHA's for completion operations using jointedtubular, wireline or cable and using coiled tubing (CT). Further it isknown to use wireline deployed within an interior of CT to actuateconventional select-fire perforation charges and to transmit signalsassociated with casing-collar locators used in depth measurement such astaught in U.S. Pat. No. 7,059,407.

As new resources are being developed, the industry has an interest infracturing operations in horizontal wells, such as wellbores which mayhave minimal vertical portions and very long horizontal wellbores. Useof coiled tubing to deploy conventional BHA's, particularly using smalldiameter CT, is problematic in such wellbores as one cannot easily runin CT to the toe of the very long horizontal wellbores.

Generally, a conventional BHA for use with CT and used for completion ofnew wellbores incorporates a jetting sub for perforation of casing orthe wellbore wall and a single sealing element, such as a resettablebridge plug, for sealing the wellbore below the jetted perforations fortreating the formation therethrough. The treatment fluid, such as afracturing fluid, is then pumped through the annulus between the casingand the CT, or through the bore of the CT, or both.

In the case of previously perforated wellbores, a separate BHA is usedwhich incorporates two spaced-apart sealing elements, such as packercups or mechanically-set or hydraulically-set packers, which straddlethe existing perforations. Treatment fluid is delivered through the boreof the CT to be delivered to the perforations isolated between thesealing elements.

Prior art tools used for performing fracturing operations at multiplezones in a formation have used wireline deployed, electrically-actuatedbridge plugs which are pumped into the wellbore. The known pump-downbridge plugs have a single, fixed diameter being slightly smaller thanthe wellbore for deployment into the wellbore and require a valve at atoe of the wellbore to get rid of fluid used to pump the bridge pluginto place. As wireline is comparatively weak and cannot pull more thanabout 2500 lbs at surface, and much less at depth, the wireline cannotbe reliably used to release or to pull the bridge plugs to surface.Thus, multiple bridge plugs must be used and left in the wellbore to bedrilled out later, at considerable expense. After the bridge plug hasbeen set, the casing is perforated with perforating guns located abovethe bridge plug. The bridge plug and the perforating guns are oftendeployed together so that both operations, isolating and perforating,can be done in the same wireline run. When the perforations have beenshot, the wireline is pulled out of the hole and the fracture fluid ispumped through the casing. Once the fracture is completed, the steps ofsetting the bridge plug and perforating followed by pumping the frac arerepeated for sequential uphole intervals until the fracturing job on thewellbore is complete. This method is commonly referred to as “plug andperf”. Following fracturing of all of the zones, the bridge plugs aredrilled out.

Conventional perforating guns are also incorporated into BHA's which areused for completion of new wellbores. Typically, conventionalperforating guns utilize detonation cord for connecting between andactuating a plurality of spaced apart shaped charges therein whichresults in a very long perforating gun. Generally, in embodiments ofconventional operations, it is desirable to perforate as many zones aspossible in a single run. In order to maximize the number zones whichcan be perforated, very long conventional select-fire perforating gunsare required. The length of the perforating guns impacts conventionaloperations, requiring very tall cranes and other support apparatus tohold and inject the very long gun assemblies and BHA into very talllubricators, often exceeding about 30 meters. In many cases, the numberof zones which can be perforated in a single trip is limited to permit areasonable length for the BHA and lubrication apparatus.

In many cases, at least two separate BHA's are required when operatorsare fracturing both new wellbores and previously perforated wellbore. Inthe case of new wellbores, once perforations are formed or a slidingsleeve is actuated to open pre-existing ports in the casing, a singleisolation apparatus is used to seal the annulus therebelow to isolatethe newly-formed perforations to be treated from the previousperforations formed therebelow. Treatment fluid can be delivered to theformation through the annulus between the casing and the ct, or, in somecases, through the CT, or through both at the same time. In the case ofold wellbores having previously formed perforations or opened portstherein, particularly where sleeves cannot be actuated to close, twospaced apart isolation apparatus are required to straddle theperforations or ports to be treated and treatment fluid is deliveredthrough the tubing string to the isolated perforations or portstherebetween.

As will be appreciated by those of skill in the art, monitoring pressuredownhole during fracturing operations is indicative of how the formationis reacting to the fracturing operation and may also be indicative ofthe integrity of the isolation apparatus and the formation betweenadjacent zones. Generally, downhole pressures are not monitoreddirectly, but instead are calculated from parameters measurable atsurface. For example, when treatment fluid is delivered to the formationthrough one or the other of the annulus or the tubing string, the othercan act as a “dead leg”. For example, when the treatment fluid isdelivered through the annulus, a minimal, constant amount of a deadheadfluid is delivered through the tubing string to act as the “dead leg”,maintaining pressure within the tubing string. The pressure required tomaintain the constant fluid delivery is monitored from surface and canbe used for calculating fracture extension pressure and formationbreakdown pressure, as well as fracture closure pressure.

It is known to use microseismic monitoring where operators wish tomonitor fracture growth and development, either in real time orretroactively to optimize subsequent fracturing operations. Prior artsystems typically require a conveniently located offset observationwellbore and wireline truck to deploy an array of sensors in theobservation wellbore, which can monitor the fracturing operation.Alternatively, an extensive microseismic surface array may be used. Bothsystems benefit from use of a multi-string shot tool (MSST) for creatingknown microseismic events as a result of detonation of string shotstherewith at known locations in the wellbore to aid in developing moreaccurate velocity profiles and calibrating the sensors.

Clearly, there is great interest in the industry to develop tools whichenable completion of multiple zones in a single trip while optimizingthe apparatus required and reducing cost and operational man hours.There is a further interest in apparatus and methods for improving theability to accurately monitor fracture growth and placement foroptimizing fracturing operations. Further, there is interest indeveloping tools having diagnostic capabilities that would greatlyimprove the reliability of the tools and processes used.

SUMMARY

Embodiments of systems and methods for completion of a wellboredisclosed herein utilize electrically-enabled coiled tubing forbidirectional communication of signals between a bottomhole assembly(BHA) and surface and for providing power to the BHA components whichcan be electrically actuated or a combination of electrically-actuatedand mechanically-actuated components. The BHA comprises at least oneelectrically-actuated, variable diameter packer located below treatmentports and which is substantially infinitely variable with respect todiameter within the limitations of the actuation mechanism. The packerhas elements which can be expanded to seal the wellbore, to act as apiston for pumping the BHA downhole and for pulling the CT therewith, orto fully retract and at any diameter therebetween.

When the BHA further comprises two or more, spaced apart, variablediameter packers, positionable on either side of treatment ports, thepackers can be individually controlled with respect to diameter foropening and closing a variety of fluid pathways between the wellbore andthe BHA having functionality heretofore impossible with conventionalcompletion tools.

In embodiments, the BHA can further comprise additional components suchas perforating apparatus, casing collar locators for locating withincased and lined wellbores, microseismic sensors, fiber optics, sensorsfor directly measuring pressure, temperature, vibration, strain andother parameters related to the BHA and completion operation. Thefurther components can be electrically-actuated or powered or can bemechanical or combinations thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a representative illustration of a bottomhole assembly BHAaccording to an embodiment of the disclosure and having a single,variable diameter packer incorporated therein;

FIG. 1B is a fanciful cross-sectional view according to FIG. 1A;

FIGS. 2A-2C are fanciful cross-sectional views of a variable diameterpacker according to FIG. 1A; more particularly,

FIG. 2A illustrates elements of the packer expanded to a slightlysmaller diameter than an inner diameter of a wellbore in which thecentralized packer is being pumped downhole by fluid drive;

FIG. 2B illustrates elements of the packer retracted to permit passageof the packer by debris in the wellbore in which the centralized packeris being pumped downhole; and

FIG. 2C illustrates elements of the packer fully retracted to permitpulling the packer uphole in the wellbore;

FIG. 3A is a representative illustration of a selectively actuatedperforating gun incorporated in a BHA according to FIG. 1A;

FIG. 3B is a cross-sectional view according to FIG. 3A;

FIG. 3C is an illustration of a plurality of segments forming a portionof an embodiment of a perforating gun assembly positioned in a wellbore,shown without the top sub or connection to the wireline orelectrically-enabled for illustrative purposes only, perforations beingshown (solid black) to illustrate the effect of detonation of shapedcharges therein;

FIG. 3D is a cross-sectional view of a segment of the plurality ofsegments, according to FIG. 3C;

FIG. 3E is a sectional view of a segment of the perforating gun assemblyaccording to FIG. 3C;

FIG. 3F is an exploded view according to FIG. 3E;

FIG. 4 is a representative illustration of a BHA according to FIG. 1A,deployed in a wellbore using electronically-enabled coiled tubing, aplurality of selectively actuated perforating gun assemblies in the BHAbeing electronically connected to a firing panel at surface;

FIGS. 5A-5D are representative illustrations of use of an embodiment ofthe BHA according to FIG. 1A for perforating and fracturing a formationaccording to embodiments of the disclosure, more particularly

FIG. 5A illustrates selective actuation of a segment of the perforatinggun for forming a perforation uphole from a previous perforation in awellbore;

FIG. 5B illustrates repositioning of the BHA to position the variablevolume packer below the perforations created in FIG. 5A; and

FIG. 5C illustrates fracturing through the perforations created in FIG.5A and above the packer, fracturing fluid being delivered through thecoiled tubing for delivery from fracturing ports in the BHA to theperforations;

FIG. 5D illustrates reverse circulation of debris from the annulus tosurface after fracturing, clean fluid being delivered through theannulus to the fracturing ports and open fluid path in the valve forcirculation of debris to surface;

FIG. 6 is a diagrammatic representation of a process for minimizingdecrease in rock stress about a previously fractured zone duringfracturing of an adjacent zone, fracturing fluid being delivered to theannulus above the packer at pressure P1 and fluid being deliveredthrough the coiled tubing to the annulus below the packer at P2, P2being greater than P1 for pressuring the formation about the previousfracture;

FIG. 7 is a representative illustration of a bottomhole assembly BHAaccording to FIG. 1A having two, spaced-apart, variable diameter packersincorporated therein, a first packer being below the fracturing portsand valve, and a second packer being above the fracturing ports andvalve;

FIG. 8A is a representative illustration of a bottomhole assembly BHAaccording FIG. 7 and having fracturing ports between the two spacedapart packers instead of a valve;

FIG. 8B is a representative illustration of a bottom hole assemblyaccording to an embodiment having equalization valves associated withfirst and second packers actuable for pressure equalization across thefirst and second packers before moving the BHA in the wellbore;

FIG. 9 is a representative illustration of a BHA according to anembodiment having microseismic sensors incorporated therein and incombination with a linear array of fiber optic sensors deployed along atleast a portion of a horizontal wellbore; and

FIG. 10 is a table representing a variety of embodiments of the BHAaccording to embodiments disclosed herein.

DETAILED DESCRIPTION

Embodiments are described herein in the context of fracturing however asone of skill in the art will understand, systems and methods disclosedherein are also applicable to other completion and stimulationoperations.

Embodiments described herein utilize electrically-actuated downholetools incorporated into a bottom-hole assembly (BHA) for completion ofmultiple zones of interest in a formation during a single trip into thewellbore. Use of electrically-actuated BHA components permitsfunctionality heretofore not seen in conventional, mechanically-actuatedBHA components. In embodiments, separate electrically-actuated drivecomponents permit independent operation of optimal BHA components, usedindividually or in combination, such as isolation apparatus, perforatingapparatus, fracturing subs, microseismic monitoring apparatus, and thelike. Further, use of the electrically-actuated tools allows the BHA tobe more compact than conventional BHA's used for the same purposes,suitable for lubricator deployment. One further advantage is that toolsincorporated in the BHA, such as perforating guns, actuated electricallyfrom surface provide accurate times of perforation and actuation offracturing operations which aid in more accurate microseismic monitoringof fracture growth and placement.

In embodiments, most, if not all, of the components of the BHA areelectrically actuated. In other embodiments, only some of the componentsare electrically actuated for maximal advantage and are used togetherwith mechanically-actuated components.

While applicable to a variety of wellbore types, apparatus and methodsdescribed herein are particularly suitable for deviated, horizontal ordirectional wellbores and particularly those of very long or extendedlength.

The terms “uphole” and “downhole” used herein are applicable regardlessthe type of wellbore; “downhole” indicating being toward a distal end ortoe of the wellbore and “uphole” indicating being toward a proximal endor surface of the wellbore. Further, the terms “electronically-actuated”and “electrically-actuated” are used interchangeably herein and may bedependent upon the characteristics of the component being actuated.

Bottom hole apparatus (BHA) 10, according to embodiments describedherein, are deployed on coiled tubing (CT) 12. Bi-directionalcommunication for actuation of the electrically-actuated tools fromsurface and receipt of data therefrom is possible usingelectrically-enabled CT 12, such as described in co-pending, USpublished application US2008/0263848 to Andreychuk, referred to hereinas electrically-enabled CT. Electrical conductors 14, such as awireline, multi-conductor cables, fiber optic cables and combinationsthereof are retained to an inner wall of the CT 12 to avoid problemsassociated with loosely hanging cabling and to permit reliable andresilient reeling and unreeling of the CT 12 during repeated operations.In an embodiment multiple conductors 14 are surrounded by an outerinsulated sheath for forming a protected cable for welding directly tothe inner wall of the CT 12, and heat treated together with the CT 12during manufacturing prior to use. The electrically-enabled CT can beused to simultaneously conduct fluid as well as electrical servicepulses and signals, as well as power.

As one of skill in the art will understand, any electrically-enabled CT12, which provides sufficient electrical capability to actuatecomponents in the BHA 10 as well as permits bi-directional communicationbetween the BHA 10 and surface, would be suitable for use in embodimentsdescribed herein.

Applicant believes that fracturing operations are particularly useful inhorizontal wells, such as wellbores 16 which have minimal verticalportions and very long horizontal wellbores, for example, wellbores withhorizontal portions extending to at a measured depth of at least 23,000feet in the Williston Basin, an area which extends from southernSaskatchewan and Manitoba, Canada into Montana, North Dakota and SouthDakota, USA. Further, fracturing operations can be performed on offshorewellbores. Coiled tubing (CT) 12 can be used in such operations. Thediameter of the CT 12, and the length of the horizontal wellbore 16which can be accessed using conventional CT-deployed apparatus andmethodologies, are largely dictated by the displacement required to pushthe CT 12 into the very long wellbores 16. Embodiments disclosed hereinpermit use of relatively small diameter CT 12, such as 1½ inchelectrically-enabled CT to deploy the BHA 10 to the toe of a very longwellbore 16. Further, use of CT 12, unlike pulling limitations ofconventional wireline, can exert much higher pulling forces dependingupon the CT size and material specifications, being sufficient to raisethe BHA 10 therefrom to surface S.

Embodiments described herein are useful for treating or fracturing newwellbores 16, both completed with casing 18 and open-hole wellbores 20,or previously perforated cased wellbores 16, or open-hole wellbores.

More particularly, an embodiment comprising first and second separatelycontrollable, spaced apart electrically-actuated variable diameterpackers 22 f, 22 s, operated as described in greater detail below, canbe used for operations in both new and old wellbores using a single BHA10. The first and second packers 22 f, 22 are substantially infinitelyvariable with respect to diameter within the limitations of theactuation means.

Embodiments described herein are used to select an optimal fracturingoperation such as that which permits reducing pumping rates and volumescompared to conventional pumping rates and volumes. Often the pumpingrates are set by the large size of CT used to access the total depth ofthe wellbore. Using embodiments describe herein permits reducing thediameter of the electrically-enabled CT 12 compared to conventional CTused for fracturing. Using conventional apparatus and methodologies,reductions in diameter of the CT 12 to a small diameter CT 12 haspresented difficulties as the small CT 12 is difficult to push to thetoe of very long wellbores 16.

Single Packer Embodiments

Having reference to FIGS. 1A and 1B, a bottom-hole assembly (BHA) 10deployable using electrically-enabled coiled tubing 12, is shown. Whendeployed into the wellbore 16, being cased 18, an annulus 34 is formedbetween the BHA 10 and the casing 18. The electrically-enabled CT 12 iscapable of conducting fluid F through a bore 38 extending therethroughas well as electrical pulses and signals through the conductors 14retained therein.

Beginning at a proximal end 40, the BHA 10 comprises at least afracturing head 55, having a plurality of fracturing ports 56 and anelectrically-actuable valve 50 therein and a first electrically-actuatedvariable diameter packer 22 f positioned therebelow.

In an embodiment the BHA 10 is fluidly connected to a distal end 42 ofthe electrically-enabled CT 12 through a ball-actuated release sub ordisconnect 44 as is understood in the art. Electrical connection betweenthe electrically-enabled CT 12 and the BHA's components therebelow canbe accomplished in a number of ways, including but not limited toconductors extending therefrom through a bore 46 of the BHA 10 orconductors extending therefrom through an electrical race formed about aperiphery of the BHA's components.

The fracturing head 55 comprises the valve 50, such as anelectrically-actuated solenoid valve. Best seen in FIG. 1B the valve 50is fluidly connected to the bore 38 of the electrically-enabled CT 12through the ball-actuated disconnect 44. The valve 50 comprises ahousing 52 having a throughbore 54 formed therethrough contiguous withthe bore 38 of the CT 12 and the bore 46 of the remainder of the BHA 10therebelow. The plurality of fracturing ports 56 extend radiallyoutwardly from the throughbore 54 through the housing 52 for delivery offluid F therethrough.

The valve 50 can be electrically-actuated to a first position to divertfluids F, flowing from the CT 12 through the plurality of fracturingports 56. When actuated to a second position, the valve 50 permits theflow of fluids F in the throughbore 54 to be delivered through the bore46 of the BHA 10 therebelow and to the annulus 34, such as through afluid crossover port 60. Valve 50 could be configured to isolate thethroughbore 54 from the annulus

The valve 50 is operatively connected to an electric valve drive 62which receives signals from surface through the electrically-enabled CT12 for controlling the position of the valve 50.

Having reference to FIGS. 1B and 2A-2C, the BHA 10 further comprises thefirst variable diameter packer 22 f operable between at least twopositions: sealed to the wellbore or undersized for pumping. When in thesealed position the first packer 22 f functions to seal the annulus 34between the BHA 10 and the casing 18 or wellbore wall 36 when actuatedto expand to a sealing diameter. The first packer 22 f further comprisesslips for anchoring the first packer 22 f in the wellbore which areactuated to engage the casing 18 or wellbore 16 when the first packer 22f is expanded to the sealing diameter.

In the second position, the first variable diameter packer 22 f is sizedto a running position, forming an uphole piston face 64 when expanded toa running diameter, being greater than a minimum packer diameter whenthe packer 22 f is in a third, fully retracted position, and less than adiameter of the casing 18 or wellbore 16. In the running position, therunning diameter of the first packer 22 f is sized to just under casingdrift. Fluid F is pumped through the annulus 34 against the upholepiston face 64 to push the first packer 22 f, and BHA 10 connectedthereto, downhole.

The running diameter is variable and depends upon a number of variablessuch as friction, horizontal length of the wellbore 16, the size andparameters related to the CT, the weight of the BHA and the like. Ingeneral the running diameter is the smallest diameter which works toeffectively move the BHA 10 downhole with sufficient pulling force topull the CT 12 therewith.

The BHA can be fit with a strain gauge (not shown) which can measureaxial load in the BHA 10 to assist the operator to understand if thepiston force on the first packer 22 f is too high and also to understandwhere resistance may be coming from, being either from debris in thewellbore 16 or as a result of drag friction of the CT 12. As one ofskill in the art will appreciate, the strain gauges or sensors providedata to surface through the CT 12 to assist with determining anappropriate balance between injection rates and pumping rates to avoidpulling the BHA 10 apart. In, other words, the CT and BHA form aninjection string, the system further comprising a strain sensor alongthe injection string uphole of the packer, such as in the BHA 10 abovethe packer 22 f, the strain sensor electrically connected to the CT forproviding signals indicative of axial loading in the string at aboutBHA. A controller is provided for receiving axial loading signals andfor managing a rate of injection of the CT and a rate of pumping of theBHA for managing the axial loading. The controller is typically locatedat surface.

Further, the wellbore 16 might be fit with a toe burst sub (not shown)to enable pump down so that fluid displaced below the first packer 22 fcan be pushed into the formation 30 at the toe of the wellbore 16. TheCT 12 is pulled therewith for positioning the BHA 10 at zones ofinterest in the formation 30 over very long horizontal wellbores, theBHA 10 placing the CT 12 in tension and effectively conveying the CT 12long distances. Further, with the first packer 22 f expanded to therunning diameter, the BHA 10 can be lifted in the wellbore using the CT12 for repositioning the BHA 10 within the wellbore 16 during fracturingfrom toe to heel. The first variable diameter packer 22 f can be reducedto the third minimum packer diameter, such as for tripping out of thewellbore 16.

In an embodiment, the first variable-diameter packer 22 f has anelectronically-actuated packer element 66 for varying the diameter ofthe first packer 22 f. The first packer 22 f is positioned below thevalve 50 and above the fluid crossover port 60 in the BHA 10. Thus, whenthe valve 50 is actuated to do so, fluid F flows through the throughbore54 to below the first variable-diameter packer 22 f and outwardly to theannulus 34 therebelow though the fluid crossover port 60.

The first variable diameter packer 22 f is electrically actuated, havinga drive sub 70 f. The first packer drive sub 70 f receives signals fromsurface S for electronically actuating the packer element 66 for varyingthe diameter of the first variable-diameter packer 22 f. In anembodiment, an electric motor 72 electrically connected to the drive sub70 f can be used for accurate and fine control of the packer diameter.In an embodiment, the electric motor 72 can drive conical actuators 74,swash plates or other means, for engaging and expanding the packerelement 66. In an embodiment, an electric motor and linear screwactuator are used to drive the conical actuators 74. Means are providedfor reducing friction and for adjusting the gear ratio between a gearratio for light load over much of the actuators stroke and a high gearratio, such as about 1:250, when the actuator engages the conicalactuators 74.

An electronics sub 80 comprising at least electronics for monitoring apressure P2 below the first packer 22 f and for optionally monitoring apressure P1 above the first packer 22 f, is also incorporated into theBHA 10, such as below the first packer 22 f and the first packer drivesub 70.

For location of the BHA 10 within the wellbore 16, the BHA 10 furthercomprises an electronic casing collar locator (CCL) 82 which is capableof detecting casing collars and which may also be capable of detectingperforations. The electronics sub 80 also comprises electronicsassociated with the operation of the CCL 82. The electronically-actuatedCCL 82 is useful throughout the completion operation for accuratelydetermining the positioning of the BHA 10 in the wellbore 16.

Alternatively, in embodiments, a mechanical CCL can be used.

Perforation Option

In a general tool for simple cased or lined wells 16 or as a backup tofailed sleeved subs, an electronically-actuated perforating apparatus 84is also incorporated into the BHA 10. Such perforating apparatus 84 maycomprise an electronically-detonated, selectively-actuated perforatinggun assembly 90, such as shown in FIGS. 3A-3F, or alternatively maycomprise perforating apparatus which are electronically orelectro-mechanically-actuated to mechanically punch or drill through thecasing 18 or liner for creating perforations therein.

In embodiments, as shown in FIGS. 1A and 1B, an electronically-detonatedselectively-actuated perforating gun assembly 90 can be mounted adjacenta distal end 152 of the BHA 10. While any type of selectively-actuatedperforating gun can be used, embodiments described herein utilize aperforating gun 90 having a plurality of segments 92 which are wired insuch as way as to permit each segment 92 to be detonated selectively andindividually, such as from a firing panel 94 at surface (FIG. 4) asdescribed in greater detail below.

In embodiments, a magnet 150 may optionally be mounted at the distal end152 of the BHA 10 for picking up metallic debris in the wellbore 16,such as during run in.

Microseismic Monitoring Option

Optionally, where fracturing of the formation 30 is monitored using amicroseismic fracture monitoring system, one or more seismic sensors140, such as axially-spaced, 3-component (x,y,z) geophones, are alsoincorporated into the BHA 10. The one or more 3-component sensors 140are incorporated in the BHA 10 between the first packer 22 f and theperforating gun assembly 90.

In embodiments, each seismic sensor 140 is coupled to the casing 18 orwellbore wall.

In an embodiment, each sensor 140 has elements or arms 142 which can beactuated, such as electronically, to contact the casing 18 or wellborewall 36 for seismically coupling the sensors 140 thereto and enhancingsignal detection when the BHA 10 is positioned for fracturing. The arms142 can be retracted any time the BHA 10 is to be moved within thewellbore 16 or removed therefrom.

Alternatively, each sensor 140 comprises conventional centralizers (notshown) which extend outwardly from the sensors 140 and which act tocouple the sensors 140 to the casing 18 or wellbore wall.

In order to accurately determine the position of a microseism resultingfrom a fracturing operation, one must know the orientation of the one ormore sensors 140 and therefore means are provided to ensure that thesensors 140 are either oriented in a known orientation when landed orthat any resulting orientation can be determined, in real time or in amemory mode, so as to permit the data to be mathematically manipulated.

In an embodiment, each of the sensors 140 is pivotally mounted withinthe BHA 10 and a housing 144 for each sensor 140 is weighted to ensurethat the sensor 140 orients to a known orientation when deployed in thewellbore, such as prior to extending the arms 142 for coupling thesensor 140 in the wellbore 16. Alternatively, the weighting of thehousing causes the sensors 140 to rest on the casing or wellbore walland no additional coupling apparatus is required.

Alternatively, in another embodiment, each of the sensors 140 hasposition sensors, such as accelerometers or MEMS sensors, which arecapable of providing signals to surface, or to a downhole processor witha battery and memory, regarding the orientation of each of the sensors140. The data from the sensors 140 is then mathematically manipulatedwith respect to the orientation of the sensors 140, as is understood inthe art.

Details of embodiments comprising the microseismic monitoring option arediscussed in greater detail below.

Electrically Actuated Variable Diameter Packers

In greater detail, and having reference again to FIGS. 2A-2C, inembodiments, in order to move the BHA 10 deployed on small diameterelectrically-enabled CT 12 to the toe of very long wellbores 16, thepacker element 66 of the first variable diameter packer 22 f isexpandable and retractable for varying the outer diameter. One positionfor the first packer 22 f is to act as a piston and be effectivelypumped downhole, pulling the small diameter electrically-enabled CT 12therewith. The first packer 22 f is centralized in the wellbore, such asusing conventional centralizing elements 124. When inserted into thewellbore, the packer element 66 of the first packer 22 f iselectronically actuated to at least two positions: to seal as a packerand to act as a piston for pumpdown purposes and could include a thirdposition, being fully retracted to minimize accidental engagement anddamage. In the second, pumpdown position the packer element 66 isexpanded in diameter to the running diameter, being a diameter less thana diameter of the wellbore 16. The increased packer diameter permitseffective generation of substantially maximal fluid force on the BHA 10.Fluid F is pumped through the annulus 34 to act at the uphole pistonface 64 of the first packer 22 f for pushing the first packer 22 f andBHA 10, and for pulling the electrically-enabled CT 12 therewith, toadjacent a toe of a very long wellbore 16. For example using 2000 psiand a 12 square inch packer face, as is the case for 4½ inch diametercasing 18, a 24,000 lb force is generated which can push the firstpacker 22 f and BHA 10 to the toe of about a 4000 m TVD wellbore 16.Depending upon the size and type of CT 12 used about 50,000 lbs to about150,000 lbs of pulling force can be exerted to raise the BHA 10 tosurface S.

Advantageously, as shown in FIG. 2B, the packer element 66 of the firstvariable diameter packer 22 f can also be temporarily varied in diameterto a third smaller diameter than the running diameter to run past debrisD encountered in the wellbore 16. Should there be an indication atsurface that the BHA 10 is not advancing in the wellbore 16, thediameter can be controllably reduced, actuated electronically, such thatthe first packer 22 f and the BHA 10 can pass the debris D, after whichthe diameter of the first packer 22 f can once again be increased to thepumpdown or running diameter for achieving substantially maximum axialdisplacement. As shown in FIG. 2C, the first packer 22 f can also beactuated to the third position for a smallest or minimum packer diameterfor tripping out of the wellbore 16.

Selectively-Fired Electrically Actuated Perforating Gun

Having reference to FIGS. 3A to 3F and 4, in an embodiment, theselectively-actuated perforating gun 90 comprises the plurality ofsegments 92 which are operatively connected to the electrically-enabledCT 12 through a top connector sub 96 at a proximal end 98 of theperforating gun 90.

As shown schematically in FIG. 3B and in greater detail in FIGS. 3C to3F, each segment 92 comprises a detonator 100 and anelectronically-actuated triggering means 102, such as a built inelectronic switch, and one or more shaped charges 104. In embodiments,the electronic switch 102 is built into a detonator housing 106 in whichthe detonator 100 is mounted. The one or more shaped charges 104 aremounted radially about the detonator housing 106. Where two or moreshaped charges 104 are used, the charges 104 are spaced from one anotherat phased angles thereabout. The one or more shaped charges 104 in eachsegment 92 can be fired from surface independently of the one or morecharges 104 in each of the other segments 92 in the perforating gunassembly 90.

In the embodiment shown in FIGS. 3A, 3C and 4, there are thirtycylindrical segments 92, stacked end-to-end, the detonator 100 andswitch 102 in each of the 30 segments 92 being electronically connectedto the firing panel 94 at surface S. In each of the thirty segments 92,there are three shaped charges 104 which are spaced circumferentiallyabout the segment 92 at about 120° from one another and in proximity tothe detonator 100 for actuation of the shaped charges 104. Perforatinggun assemblies 90, according to embodiments of the disclosure, arerelatively short compared to conventional perforating gun assemblies. Inan embodiment, each of the perforation segments 92 is less than about180 mm in length. A perforating gun assembly 90 having thirty segments92 is therefore less than about 5.5 m in length.

As shown in FIGS. 3C to 3E, and in an embodiment, the shaped charges 104in each segment 92 are operatively connected to the detonator/switch100,102 by positioning the charges 104 in close proximity to a primerend or blasting cap 108 of the detonator 100 housed in the segment 92.Thus, the perforating gun 90 does not require detonation cord to be runand connected between each of the segments 92 and can be made muchshorter than perforating guns which rely on detonation cord to transmitthe detonation to shaped charges spaced further away.

As shown in FIGS. 3E and 3F, the detonator 100 is mounted in thedetonator housing 106. The switch (not shown) is built into thedetonator housing 106. The detonator housing 106 is supported by aconnection ring 110 for insertion into an upper housing 112 of thesegment 92. Electrical connections, between the top sub 96 and theswitch 102 and detonator 100 can be tested for each segment 92 at thisstage of assembly to ensure the connections are viable, without dangerof actuating the shaped charges 104. The electrical connections arethrough conductive pin connections 114 at proximal 116 and distal 118ends of the detonator housing 106.

Once the electrical connections have been tested and verified, theshaped charges 104 are inserted into a shaped charge retainer 120. Thedetonator housing 106 passes though a bore 122 in the center of theshaped charge retainer 120 for positioning the charges 104 adjacent theprimer end 108 of the detonator 100 therein and is secured therein forco-rotation with the shaped charge retainer 120 as it is threaded intothe upper housing 112. In embodiments, the detonator housing 106 hasslots formed therein which engage forks on the shaped charges 104 forsecuring the detonator housing 106 to the shaped charge retainer 120.

A pin connector housing 128 is threaded into a distal end 130 of theshaped charge retainer 120. The pin connector housing 128 can also bethreaded to the shaped charge retainer 120 prior to insertion of theshaped charges 104.

Thereafter, a lower tubular housing 132 is positioned over the shapedcharges 104 to complete the segment 92 and the upper housing 112 of asubsequent segment 92 is threaded onto the pin connector housing 128,sandwiching the lower tubular housing 132 therebetween. The detonator100 and detonator housing 106 supported in the subsequent segment 92extends into the pin connector housing 128 so as to permit an electricalconnection between the conductive connection pin 114 on the distal end118 of the detonator housing 106 in the first segment 92 with theconductive connection pin 114 on the proximal end 116 of the detonatorhousing 106 in the subsequent segment 92.

Following testing of the electrical connection for the subsequentsegment 92, the shaped charges 104 can be loaded therein as describedabove. Thus, a perforating gun 90 according to this embodiment islengthened a segment 92 at a time. Each switch 102 built into thedetonators 100 is independently triggered by the firing panel 94. Thus,there is little to no danger that a segment 92 having the charges 104loaded therein can be actuated when the electrical connections aretested in another segment 92 being added.

In embodiments, a single conductor 134 connects all segments 92 in theperforating gun assembly 90 and each segment 92 comprises means forindependently triggering shaped charges 104 mounted in each segment 92.The shaped charges 104 are typically detonated from a bottom segment 92of the gun 90 to a top segment 92 of the gun 90 as the conductor 134 maybe damaged by detonation of the shaped charges 104.

The firing panel 94 may be connected to the plurality of segments 92through the single conductor 134 connected to all of the detonators 100having switches 102 located at the detonator 100. Alternatively, thefiring panel 94 can be connected through multiple conductors 134 n.

As shown in FIG. 4, perforating gun assemblies 90 having any desirednumber of segments 92 are possible according to embodiments describedherein. Where perforating guns 90 with segments 92 in excess of abouttwenty to about thirty segments 92 are desired, one or more additionalwires can be run from the top sub 96 to one or more tandem subs to whicha further about twenty to about thirty or more segments are connected aspreviously described. In this way, the conductance is optimizedthroughout all of the segments 92 between the top sub 96 and the tandemsub where tandem subs are used to lengthen the perforating gun 90 andincrease the number of segments 92 which can be used in a single run.

For example, each thirty-segment perforating gun assembly, having 3shaped charges 104 in each segment 92, can create ninety perforations.If multiple, thirty-segment perforating gun assemblies 90 are stackedend-to-end and electrically connected to the firing panel 94, multiplesof the ninety perforations can be performed in a single trip. The shapedcharges 104 in one segment 92 can be fired at a zone of interest or theshaped charges 104 in more than one segment 92 can be detonated toincrease the number of perforations in the zone. The same firing panel94 used to actuate the switches 102 and detonators 100 of a single,thirty-segment assembly 90 is used to actuate the additionalthirty-segment assemblies 90. Once the first thirty segments 92 havebeen fired, a switch 136 can be flipped at the firing panel 94 toactuate a second or even third set of segments 92 in another of theassemblies 90. In this case, perforation of very long wellbores 16 canbe accomplished without having to pull the BHA 10 from the wellbore 16.

The switch 102 and detonator 100 in each segment 92 receives theelectronic signal transmitted from the firing panel 94 at surface,through the electrically-enabled CT 12, and responds to actuatedetonation of the shaped charges 104 in the selected segment 92 withinabout 0.5 ms. Time of firing is therefore known within about 0.5 ms.

By way of example only, detonators 100, switches 102 and firing panel 94systems, suitable for use in embodiments described herein, are availablefrom DYNAenergetics GmbH & CO. KG, Laatzen, Germany.

The exact time of firing of the perforating gun 90 as described abovecan be particularly advantageous when the wellbore 16 is to be fracturedfollowing perforation and if a microseismic fracture monitoring systemis in place to monitor the growth and placement of the fractures. Thefiring of the perforating guns 90 creates noise events in the wellbore16 to be fractured which can be used, in combination with the accuratetiming of detonation, to improve development of velocity profiles,sensor orientation and sensor calibration used in the microseismicmonitoring.

Microseismic sensors 140, positioned at least at surface, such as in anarray, and/or the sensors 140 incorporated in the BHA 10, are able todetect the noise events resulting from the detonation of the shapedcharges 104 or the perforation of the casing 18. The data, incombination with the accurate time of initiation of the noise events, isparticularly useful in calculating a velocity profile for the formationto be fractured.

Generally, the shaped charges 104 in each segment 92 are detonated atdifferent locations in the wellbore 16. The firing panel 94 at surfaceis used for firing the shaped charges 104 in each of the perforating gunsegments, as desired. For example, the shaped charges 104 in a firstdistal perforating gun segment 92 are fired when the perforating gun 90is located at a first location in the wellbore 16, such as adjacent atoe of the wellbore 16. Thereafter, the perforating gun 90 isrepositioned to a second location in the wellbore 16 and the shapedcharges 104 in a second of the segments 92 are fired. The repositioningand firing of the shaped charges 104 is repeated for the remainingsegments as the perforating gun 90 is relocated toward the heel oruphole within the wellbore 16.

Embodiments disclosed herein further comprise fluid isolation betweensegments 92 of the perforating gun 90 such that when the shaped charges104 are detonated, fracturing fluid F and the like cannot flow betweensegments 92. As shown in FIG. 3E, the pin connection housing 128provides fluid isolation between the adjacent segments 92.

In embodiments where the perforating apparatus 84 is anelectrically-actuated punch tool or electrically-actuated drillingassembly or the like, the tool can be electrically-actuated from surfaceto form any number of perforations in the casing in each zone ofinterest. In this embodiment, the number of perforations which can bemade is not limited by the perforating apparatus 84 as is the case inthe perforating gun 90 which has a fixed number of shaped charges 104therein.

New Wellbores

Single packer embodiments as described herein are particularly suitablefor use in new wellbores. New wellbores 16 are drilled, but have not yetbeen completed. Further, new wellbores 16 can be cased 18 and which haveported sliding sleeve subs 24 installed therein, sliding sleeves 26therein having not yet been actuated for opening ports 28 in the portedsubs 24 to access formation 30 therebeyond. In embodiments, the slidingsleeves 26 may also be selectively closable to stop communicationbetween the formation 30 and a bore 32 of the casing 18 therethrough.

In Use in New Cased or Lined Wellbores

In use, as shown in FIGS. 2A-2C, 4, and 5A-5C, the BHA 10 is connectedto the electrically-enabled CT 12 and is injected into the wellbore 16through a lubricator 160. As the BHA 10 is relatively compact, thelubricator 160 has a height which is much shorter than required for aconventional single-trip BHA. In embodiments, the lubricator 160 isabout 12 m compared to 20 m to 30 m and greater required for aconventional BHA. Further, surface equipment 162, such as cranes, can beused to raise embodiments of the BHA 10 compared to equipment requiredto raise and inject longer conventional BHA's.

Once run into the wellbore 16, as shown in FIG. 2A, the packer element66 of the first packer 22 f is electronically actuated to expand to therunning diameter. Fluid F is pumped into the annulus 34 formed betweenthe electrically-enabled CT-deployed BHA 10 and the wellbore wall 36 orcasing 18 for acting at the uphole piston face 64 of the expanded packerelement 66 for pumping the first packer 22 f and the BHA 10 connectedthereto into the wellbore 16, such as to a toe 164 of the wellbore 16(FIG. 4). The electrically-enabled CT 12 is pulled downhole with thefirst packer 22 f and the BHA 10. Typically the BHA 10 is run into thetoe 64 as fracturing is performed at intervals or zones of interest fromthe toe 164 of the wellbore toward a heel 166 of the wellbore 16.

As shown in FIG. 5A, when the BHA 10 is accurately positioned, using theCCL 82, the perforating gun 90 is adjacent a non-perforated zone ofinterest in the formation 30. A select detonator 100 and switch 102 in asegment 92 of the selectively actuated perforating gun 90 iselectronically-actuated from the firing panel 94 at surface S forperforating the wellbore 16 or casing 18, if cased. Where the wellbore16 is cased and the casing 18 is cemented into place, the cement C mayalso be perforated by the explosion of the shaped charges 104.Alternatively, one may simply pump fracturing fluid F, at fracturingpressures, through the perforations in the casing 18, to fracture thecement and access the formation, as is understood in the art.

Thereafter, a shown in FIG. 5B, the BHA 10 is repositioned such that thefirst packer 22 f is positioned below the latest or most recently formedperforations and above any previous perforations. The packer element 66of the first packer 22 f is electrically-actuated to expand to thesealing diameter to seal the first packer 22 f against the wellbore 16or casing 18 and isolate the annulus 34 therebelow.

As shown in FIG. 5C, the valve 50 is electrically-actuated to the firstposition to flow treatment fluid F, at fracturing pressures, from the CT12 through the throughbore 54 to exit the fracturing ports 56 to theannulus 34 above the first packer 22 f for delivery through the latestperforations P to the formation 30 therebeyond.

Having reference to FIG. 5D, when the zone of interest has beenfractured, the valve 50 can either be shut off to stop the flow of fluidF through the bore 46 of the BHA 10 or maintained open to permit reversecirculation of debris D from the annulus 34 to surface S through thebore 38 of the electrically-enabled CT 12 by flowing a clean fluid Fcdown the annulus 34. Alternatively, clean fluid Fc can be circulateddown the bore 38 of the electrically-enabled CT 12 with reversecirculation of debris D to surface S through the annulus 34. The abilityto open and flush the first packer 22 f permits the operator to run witha higher sand density, even risking sand off because of the ease withwhich one can recover. One can fully retract the first packer 22 f andcirculate the sand out of the well.

When a fracture is complete, one can use CT strain sensors to determinewhether downhole conditions have changed, such as due to temperatureeffects resulting in residual set-down or pull-up on the first packer 22f. CT set-down or pull-up load can be adjusted accordingly to protectthe packer 22 f.

The first packer 22 f is thereafter released from the wellbore 16 byelectronically-actuating the packer element 66 to reduce to the runningdiameter to unseal from the wellbore (FIG. 2A) and permit relocation ofthe BHA 10 through the wellbore. Release of the packer 22 f can alsoinclude actuation of an equalization valve to equalize the pressureacross the packer 22 f before or at the same time as the packer 22 f isreleased.

Electric motors in the first packer drive sub 70 f actuated to reducethe diameter of the first packer 22 f, turn a shaft which, in turn,moves a mandrel having a valve thereon which opens prior to release ofthe packer element 66 to release pressure above and below the firstpacker 22 f. Having reference to FIGS. 1B and 6, as pressure can bemonitored above and below the first packer 22 f, using pressure sensors170 positioned for monitoring the pressure P1 in the annulus 34 abovethe first packer 22 f and the pressure P2 in the annulus 34 below thefirst packer 22 f. one can monitor the pressures P1, P2 until equalizedprior to unseating the first packer 22 f and moving the BHA 10.

The BHA 10 is then lifted using the electrically-enabled CT 12 toposition the perforating gun 90 adjacent the next zone of interest,uphole from the previously perforated and completed zone. Once again, asegment 92 of the perforating gun 90 is electronically actuated usingthe firing panel 94 at surface S and the shaped charges 104 in anotherof the segments 94 are detonated. Fluid F is pumped against the pistonface 64 of the first packer 22 f for moving the BHA 10 downhole forpositioning the first packer 22 f below the newly created perforations Pin the uncompleted zone. Once in position, the packer element 66 iselectronically actuated from surface S to expand to the sealing diameterto seal against the wellbore wall 36 or casing 16 and the fracturingoperation is repeated, as described above.

In conventional completion operations, a “dead leg” is used not only toprevent collapse of the CT 12 under pressure from fluids in the annulus34, but also to permit calculation of pressure to determine reaction ofthe formation 30 to the fracturing operation.

In embodiments described herein, and having reference again to FIGS. 1Band 6, the downhole electronic capabilities provided by theelectrically-enabled CT 12 and connections within the BHA 10 permitdirect measurement of parameters such as pressure, temperature,vibration and the like. Pressure sensors 170 are positioned formonitoring the pressure P2 in the annulus 34 below the first packer 22f. The pressure sensors 170 are electrically connected to theelectronics sub 80 for transmission of data to surface S via theelectrically-enabled CT 12. While a pressure P1, above the first packer22 f, can be calculated at surface S, the electronics sub 80 can also beelectrically connected to pressure sensors 170 which directly monitorthe pressure P1 in the annulus 34 above the first packer 22 f. As willbe appreciated by those of skill in the art, pressure P1 above the firstpacker 22 f is indicative of how the formation 30 is reacting to thefracturing operation while pressure P2 below the first packer 22 f maybe indicative of the integrity of the packer element 66 of the firstpacker 22 f and the formation 30 between adjacent zones. Further, afterstopping pumping of the fracture fluid F, fracture closure pressures canalso be monitored.

The ability to measure pressures may be particularly advantageous whenhigh rate foam fracturing is performed as measuring pressure enablesunderstanding of the quality of the foam at the perforations.

Cased Wellbores with Sliding Sleeves

As shown in FIG. 1A, it is known to incorporate a plurality of theported sliding sleeve subs 24 into the casing 16 or in a liner in awellbore 16. The sliding sleeves 26 are opened for opening thepre-existing ports 28 in the casing 18, minimizing the need to perforatethe casing 18 for accessing the formation 30 therebeyond. In some cases,the opened sliding sleeves 26 can also be actuated to close forisolating portions of the formation 30 from fluids flowing through thecasing 18.

In embodiments, as taught in Applicant's co-pending U.S. applicationSer. No. 13/773,455, the entirety of which is incorporated herein, theBHA 10 further comprises a CCL 82 which can be mechanical or electronicand which detects collars between joints of casing 18, rather than abottom of the sliding sleeve 26, as in the prior art. Thus, the CCL 82is used to locate the BHA 10 based on a location of the casing 18 orlocating collar adjacent and downhole of the ported sliding sleeve sub24. Accordingly, the length of the ported sub 24 and sleeves 26 do notneed to be a function of BHA length and therefore not as long as theprior art. The CCL 82 does not need to be a specialized CCL fordetecting a profile at the lower end of the prior art ported sub andsliding sleeve therein.

In embodiments, the CCL 82 is spaced below the first packer 22 f, suchas by a length of relatively inexpensive pup joint, positioning the CCL82, when engaged, to appropriately position the fracturing ports 56 ator near the pre-existing ports 28 in the ported sub 24 when the CCL 82engages the locating collar 19. In embodiments, the downhole end of theported sub 24, the locating collar 19 or lengths of adjacent casing 18are aggressively profiled to assist detection by the CCL 82.

In embodiments, when the CCL 82 locates the BHA 10 for positioning thefracturing ports 56 adjacent the open ports 28 in the ported sub 24, thefirst packer 22 f is located below the open ports 28. The first packer22 f, when electrically-actuated to the sealing diameter, acts toisolate the annulus 34 therebelow from fracturing fluids F which can bedelivered to the fracturing ports 56 in the BHA 10 either through theelectrically-enabled CT 12 for delivery to the open ports 28 in thecasing 18, directly to the open ports 28 in the casing 18 through theannulus 34 above the first packer 22 f, or through both.

In embodiments where the CCL 82 is an electronically-actuated CCL,detection of an end of the ported sleeve sub 24 can be accurate withinmillimeters. The accuracy of detection of the location of the sleeve sub24 further permits the ported sleeve sub 24 to be much shorter than aconventional sleeve sub. The reduction in length significantly reducesthe cost of the sleeve subs 24 and the BHA 10. In embodiments, both thesleeve sub 24 and the BHA 10 are reduced in length to about one-half orless that of a conventional sleeve sub and BHA. In embodiments, the BHA10, excluding the length of the perforating apparatus 84, is about 4 mto about 5 m.

Sleeves 26 can be opened using a variety of conventional sleeve openingand closing techniques, including but not limited to setting the firstpacker 22 f within the sleeve 26, expanding the packer element 66 andthereafter utilizing fluid F to force the first packer 22 f and sleeve26 to shift the sleeve 26 axially therein, electronically ormechanically actuating a shifting tool (not shown) incorporated in theBHA 10 to engage the sleeve 26 and shift the sleeve 26 axially thereinor by actuating a rotational opening tool to engage the sleeve 26 forrotation to an open position. Alternatively, differential pressure canbe used to hydraulically open the sleeve 26.

In embodiments, where there has been a failure of the sliding sleeve 26to open, the selectively actuated perforating gun assembly 90 can beused to perforate the ported sub 24. Further, the perforating gunassembly 90 can be used to create perforations in the casing 18 at zonesof interest where there are no sliding sleeve subs 24.

In Use-Cased Wellbores with Ported Sleeve Subs

Once the sleeve 26 has been moved to open the ports 28 in the portedsleeve sub 24 or perforations P have been made through the casing 18 orported sub 24, where sleeves 26 did not exist or failed to open,treatment therethrough proceeds as previously described above.

In embodiments, following treatment, the ports 28 in the ported sleevesubs 24 are closed, as is understood by those of skill in the art.

Multiple Packer Embodiments

In embodiments, having reference to FIG. 7, the BHA 10 further comprisesat least the second, variable diameter packer 22 s, spaced uphole fromthe first variable diameter packer 22 f and the valve 50. Embodimentshaving two packers 22 f,22 s are particularly suitable for use inpreviously perforated wellbores, newly perforated wells having all ofthe zones perforated therein, wellbores having sleeves 26 which are inthe open position or in openhole wellbores 20.

The first and second variable diameter packers 22 f,22 s straddle thefracturing ports 56. In embodiments, a second packer drive sub 70 spositioned below the second packer 22 s is electronically actuated tovary the diameter of the packer element 66 in the second packer 22 s.Optionally, the first packer drive sub 70 f may be electricallyconnected to both the first and second variable diameter packers 22 f,22s and is capable of independently electronically actuating packerselements 66 in both the first and second packers 22 f, 22 s. In eithercase, the packer elements 66 of the first and second packers 22 f, 22 sare independently variable with respect to diameter.

New Wellbores

While a separate BHA 10 having the first and second packers 22 f, 22 scan be used for previously perforated or openhole wellbores, due to theindependent controllability of the variable diameter packers 22, thesame BHA 10 used for the previously perforated wellbores 16 is also usedfor new wellbores 16. The second packer 22 s may simply not be usedduring the fracturing operation. In this case, the second packer 22 smay be used to assist in moving the BHA 10 within the wellbore byincreasing the diameter of the packer elements to the running diameterbut it is thereafter reduced to the minimum packer diameter once the BHA10 is positioned with the first packer 22 f below the perforations P oropened sleeve 26. Thus, during the subsequent fracturing operationtreatment fluids F can be delivered through the annulus 34 to theperforations P, as well as through the bore 38 of theelectrically-enabled CT 12.

Use of one tool suitable for new or old wells reduces inventory andimproves standardization.

Perforated Wellbores

Previously perforated or newly perforated wellbores 16 are wellbores 16that have had perforations P made in the casing or liner 18 forproduction of formation fluids therethrough. During the life of thepreviously perforated wellbore 16, there may be a need to stimulateproduction from the formation 30 or otherwise treat the formation 30,such as by fracturing. As the existing perforations P whether newly madeor existing, wherever they occur along a length of the wellbore 16,provide fluid connections to the formation 30, select perforations P ata zone of interest must be isolated from the remaining perforations Pfor treatment of only the zone of interest.

Cased Wellbores with Open Sliding Sleeves

Previously perforated wellbores 16 may also be wellbores 16 havingported sleeve subs 24 incorporated therein which have been previouslyopened by shifting or rotating sleeves 26 which thereafter have not orcannot be closed.

In Use in Cased, Perforated Wellbores or in Openhole Wellbores

The BHA 10 is lowered into the wellbore 16 until the perforations P atthe zone of interest are located between the first and second variablediameter packers 22 f,22 s. One can use a CCL to position the BHA 10 asdescribed above. Once in position, the first and second packers 22 s,22f are independently electrically-actuated to expand the packer element66 to the sealing diameter, straddling the perforations P therebetween.Fracturing fluid F is delivered through the electrically-enabled CT 12and exits the fracturing ports 56 to the formation 30 isolated betweenthe first and second packers 22 f, 22 s or through the perforations P tothe formation 30 therebeyond.

Perforation Option

Where a zone of interest has not been previously perforated, thediameter of the packer element 66 of at least the second variablediameter packer 22 s is expanded to the running diameter for pumping theBHA 10 downhole. The first packer 22 f, below the valve 50 andfracturing ports 56 can be at a smaller diameter than the second packer22 s or can also be at the running diameter during pumping downhole. TheBHA 10 is pumped downhole as described above to position the perforatingapparatus 84, such as the perforating gun assembly 90, adjacent thenon-perforated zone of interest and a segment 92 of the perforating gunassembly 90 is actuated electronically from surface to perforate thecasing or liner 18.

Thereafter, the BHA 10 is pumped further downhole to position the newlyformed perforations P between the first and second packers 22 f,22 s.The packers 22 f,22 s are thereafter independentlyelectronically-actuated to the sealing diameter on either side of thenewly formed perforations P and the fracturing operation is performed,as previously described.

In embodiments having the first and second variable diameter packers 22f,22 s, the electronics sub 80 further comprises electronics connectedto additional pressure sensors 170 for monitoring the fracturingpressure P3 between the first and second packers 22 f,22 s.

In an embodiment, as shown in FIG. 8A, in contrast to the embodimentshown in FIGS. 1A, 1B and 7, the fracturing head 55 may not require avalve between the first and second variable diameter packers 22 f,22 s.Fracturing ports 56 can be in constant fluid communication with the bore38 of the electrically-enabled CT 12 for delivery of treatment fluid Ftherethrough to the fracturing ports 56 to the annulus 34 and to theformation 30 through the perforations P.

Optionally, embodiments may comprise a safety valve 180, such as a ¼turn electrically-actuated valve or manual check valve, positionedbetween the disconnect 44 and the second packer 22 s. Should there be adisconnect to leave the tool downhole, the safety valve could be used toprevent flow uphole through the CT 12.

Openhole Wellbores

In the case of openhole completions, as there are no casing collars tolocate using the CCL 82, the BHA 10 is positioned in the wellbore 16using depth control means such as a logging tool or a depth measurementtool at surface which measures the length of CT 12 deployed. The firstand second packers 22 f,22 s are positioned adjacent the zone ofinterest and the packing elements 66 are expanded to the sealingdiameter for sealing against the uncased and unlined wall 36 of thewellbore 16.

Pressure Equalization—Single and Multi-Packer Embodiments

With reference to FIG. 8B, another embodiment of a two packerarrangement is provided, illustrated in cased wellbore, in which boththe first, downhole packer 22 f is electrically actuable and the second,uphole packer 22 s is also electrically actuable. The first packer 22 fincludes slips 171 for securing the BHA in the wellbore. The firstpacker 22 f is associated with a bypass or equalization valve 23 f forreleasing differential pressure across the packer 22 f before releasing.Equalization ports 25 f fluidly communication between the CT bore 38 andthe annulus 34. The equalization valve 23 f operates the ports 25 fbetween open and closed positions and is actuated by the first packerdrive sub 70 f, first opening the valve 23 f and then releasing thepacker 22 f.

Similarly, the second packer 22 s is associated with a bypass orequalization valve 23 s for releasing differential pressure across thesecond packer 22 s before releasing. Equalization ports 25 s fluidlycommunication between the CT bore 38 and the annulus 34. Theequalization valve 23 s operates the ports 25 s between open and closedpositions and is actuated by the second packer drive sub 70 s, firstopening the valve 23 s and then releasing the packer 22 s.

In one embodiment, to move the BHA 10, one would release the uphole,second packer 22 s, by first equalizing pressure across the packer,electrically-actuating the second packer 22 s to release from thesealing diameter to the running diameter or the minimum diameter. Asstated above, one can monitor the pressure above and below the secondpacker 22 s and above and below the first packer 22 f using pressuresensors 170 (P1, P2 and P3). Thereafter, one prepares to release thedownhole, first packer 22 f, by equalizing pressure across the firstpacker 22 f and checking for undue stain in the BHA above the firstpacker 22 f. CT set-down or pull-up load can be adjusted accordingly toprotect the packer 22 f. The CT can be injected or pulled to neutralizeresidual axial forces on the BHA before releasing the slips. If theslips 171 are released before neutralizing the strain, the packer 22f,22 s could be damaged. Once strain has been neutralized, the firstpacker 22 f is the electrically-actuated to release from the sealingdiameter to the running diameter or the minimum diameter. The BHA 10 canbe moved to another position or pulled out of hole.

As discussed, the variable electrically-actuated packer is usable as apump-down piston configuration, however as the pumping forces can bevery large and the rate of the injection is determined separately, thereis the risk of over-run injecting and backing up of the CT 12 in thewellbore 16, or an under-running of the injector resulting in largetensile forces in the CT 12. A failure of the BHA 10 and CT 12 ispossible, resulting in loss of the BHA 10.

While the BHA 10 is secured in both the cased or openhole wellbore 16 asa result of pressure balancing across the two packers 22 f, 22 s, slips171 can also be set in at least the first packer 22 f for securing theBHA 10 in the wellbore 16.

Mechanical Release—Single and Multi-Packer Embodiments

As one of skill will appreciate, the BHA 10 further comprises mechanicalrelease mechanisms, such as shear pins or pressure-actuated dogs and thelike as are understood in the art, for releasing the first and secondpackers 22 f,22 s from the wellbore 16 in the event that the BHA 10becomes stuck in the wellbore 16. Use of such release mechanisms avoidsthe need to disconnect the BHA 10 unless absolutely necessary.

Microseismic Monitoring—Single and Multi-Packer Embodiments

In embodiments disclosed herein and as described in Applicant'scopending U.S. provisional application 61/774,486, incorporated hereinby reference, using at least one sensor 140, such as a geophone,accelerometer or the like, integrated into the BHA 10, the at least onesensor 140, typically a 3-component sensor, detects compressional waves(P) and shear waves (S) from microseismic events in the wellbore andoutside the wellbore. However, one cannot easily separate signals fromthe event of interest from signals derived from noise occurring as aresult of apparatus used for pumping the fracture and other inherentnoise events.

As shown in FIG. 9, fiber optic distributed sensors 190, such as thosein one or more optical fibers deployed in the wellbore 16 and which spana length of the wellbore, are capable of detecting P-waves, but do nottypically detect S-waves. The one or more optical fibers or linear arrayof fiber optic sensors 190 are capable of detecting energy originatingfrom within the formation 30 adjacent the wellbore 16. The detectedenergy can be used only to estimate distance away from the linear array190 at which the energy originated, but not the direction and thus isnot particularly useful in positioning the event in the formation 30.

Applicant believes that the combination of the ability to obtain bothP-wave and S-wave data, using at least one sensor 140 deployed adjacentthe microseismic event (fracture), and the ability to obtain a largeamount of signals from the plurality of P-wave sensors in the lineararray of fiber optic distributed sensors 190 extending along the lengthof the wellbore 16, would permit one of skill to more accuratelydetermine the position of the signals from the desired microseismicevent (fracture) while removing background noise. The fiber opticdistributed sensors 190 are utilized for mapping the background noise inthe wellbore, the noise mapping being useful to “clean up” the dataobtained from the at least one sensor 140.

Further, because positioning of the microseismic event (fracture) isfrom within the wellbore 16, Applicant believes that only a minimalsurface array or possibly no surface array is required. Further, if nosurface array is required, there is no need for a velocity profilebetween wellbore 16 and surface.

In an embodiment, therefore, at least one 3-component sensor 140 isincorporated into the BHA 10 which is used for performing a fracturingoperation and which is deployed into the wellbore on coiled tubing (CT).

More particularly, three orthogonally oriented geophones in each sensor140 provide several benefits. The first is simply to account for theuncertainty in where the source of incident energy originated. By having3 orthogonal geophones in each sensor 140, one is able to captureincident energy arriving from any direction. Since any single geophoneis only capable of capturing motion in a single direction, at least 3oriented orthogonally in each sensor 140 permit capturing motion in anyone arbitrary direction.

Secondly, with the ability to detect motion in any direction, one cancapture both compressional (P) waves, having particle motion in thedirection of propagation, and shear (S) waves, having particle motionperpendicular to the direction of propagation, with equal fidelity.

Thirdly, by measuring the difference in arrival time between theobserved compressional and shear wave arrivals for a single event, incombination with an understanding of the local velocity structure, adistance from the 3-component sensor 140 can be calculated for theorigin of that event.

Fourthly, both azimuth and inclination of the waveform impinging on thesensor can be determined. By a process referred to as hodogram analysis,which involves cross-plotting the waveforms recorded on pairs ofgeophones, the direction of arrival at any 3-component sensor 140 can bedetermined, to within 180 degrees. Effectively, the vector defining thedirection from which the energy impinged on a single 3-component sensor140 would have a sign ambiguity. The direction of arrival could beeither (x,y,z) or (−x,−y,−z).

By adding a second 3-component sensor 140 at some distance from thefirst sensor 140, directional ambiguity can be substantially eliminated.The second 3-component sensor 140 permits measurement of a time delaybetween the observed P or the observed S wave arrivals on each of thefirst and second 3-component sensors 140. One can then tell which of thetwo, possible arrival directions is the correct one. The only problem isif the event origin is located on the plane that bisects the first andsecond 3-component sensors 140, which, in reality, is most likely due tonoise contamination, the region of ambiguity likely being larger thansimply the bisecting plane. Adding a third 3-component sensor 140,spaced some distance from the first and second 3-component sensors 140,substantially eliminates the final uncertainty.

Further, at least one or more fiber optic distributed acoustic sensors190 are operatively attached to an inside of the coiled tubing CT, as isunderstood in the art, and are spaced to extend along at least a portionof the length of the wellbore 16.

Noise, such as caused by the frac pumps, sliding sleeves, fluid movementthrough the CT 12 and the like, is readily transmitted by the metal CT12. The fiber optic distributed sensors 190, in contact with a wall ofthe CT 12, readily detect the transmitted noise. A baseline can beobtained prior to turning on the pumps and initiating the fracturingoperation to assist with mapping the noise once the operation isinitiated. Furthermore, by actively monitoring the noise within thewellbore 16 using the linear array of fiber optic sensors 190, estimatesof the noise at the at least one 3-component sensor 140 can be made. Thenoise estimates can then be subtracted from the 3-component sensor data,such as obtained during fracturing. Subtracting the noise from the3-component sensor data effectively improves the ability of the3-component sensors to detect a microseismic event resulting from thefracturing and a signature thereof.

As the fiber optic distributed sensors 190 are sensitive to tensileloading, the optical fibers are embedded in an adhesive or othermaterial which is not compressible, but which is suitably flexible forCT operations. Thus, any strain changes imparted to the optical fibersare as a result of the microseisms and not to strain imposed bydeploying the optical fibers in the CT 12.

In embodiments, surface probes such as in an array about the wellbore,are not required. Optionally however, a surface array of sensors can beused.

As shown in FIG. 9, three or more, 3-component-type geophones 140 areincorporated into the BHA 10. The three or more geophones 140 are spacedfrom each other along a length of the BHA 10 and are isolated from theflow of fracturing fluid, such as by being positioned downhole from thetreatment head 55, incorporated therein.

Data collected by the geophones 140, situated in the wellbore 16adjacent the fracturing events, can be transmitted to surface in realtime, such as through the electronically-enabled CT 12 or the system canbe operated in a memory mode, the data being stored in the geophones 140for later retrieval.

As is understood by those skilled in the art, both power and signals canbe transmitted using a single wire. In embodiments, a separate wire isincorporated in the electrically-enabled CT for operating themicroseismic sensors 140 and a separate wire is incorporated foroperating the other components of the BHA 10.

In embodiments, fiber optics incorporated into the electrically-enabledCT may be used to send data to surface from all of the BHA components,including the microseismic sensors 140.

Based upon conventional microseismic monitoring performed remote fromthe wellbore 16, one of skill would have thought it desirable to spacethe geophones as far apart as possible in the wellbore, such as by about100 m, to provide optimum time resolution therebetween. Practicallyspeaking however, when deployed with the BHA, the spacing between thegeophones is limited by the size of the lubricator 160 at surface forinjecting the BHA 10 into the wellbore 16. In embodiments, the geophones140 are placed at least about 1 m apart. In embodiments, the geophones140 are placed at about 5 m to about 10 m apart. However, because thegeophones 140 are positioned so close to the fracturing events andbecause there is replication of the arrival times of both thecompressional (p) and shear (s) waves at each of the geophones 140permitting calculation of distance, calculation of velocity becomes lessimportant and thus, the closer spacing is satisfactory. For example, ina conventional arrangement of sensors, a 10% error in velocity becomessignificant by the time the signals reach a distant surface orobservation well array. In embodiments disclosed herein however, whenthe geophones 140 are placed so close to the fracturing event, velocitybecomes less significant, particularly as there are fewer interveninglayers between the event and the sensors 140 through which the signalmust pass.

Applicant believes that the frequency of noise generated through pumpingof the fracture may be at a higher frequency than that of themicroseismic event outside the wellbore (lower frequency). However, evenif the frequencies are substantially similar, Applicant believes thatthe event can be recognized and any effects of the lower frequenciesnoise can be minimized, according to embodiments disclosed herein.

It is assumed that the acoustic noise, such as from fluid flows ortravelling through metal casing 18, tubular and the like, are lineartrends and that only one component of a 3 component geophone 140 will beaffected by the noise. In reality, Applicant believes the other twocomponents will likely also detect at least some of the noise.

As previously described, the three or more geophones 140 are coupled tothe casing 18 or wellbore 16 and the orientation of each of thegeophones 140 is known or can be mathematically adjusted for orientationand thereafter interpreted.

Applicant believes that the addition of the linear array of fiber opticsensors 190, used in combination with the three or more geophones 140produces signals sufficiently clean to permit accurate determination ofthe position of the microseismic event within the formation 30. Noisemapped from the fiber optic sensors 190 is removed from the signals ateach of the three geophones 140 and the clean signals are thereafterused to locate the microseismic event (fracture), as is understood bythose of skill in the art.

Optionally, the sensors 140 may be decoupled from the remainder of thecomponents of the BHA 10 to reduce noise associated therewith.

Monitoring of microseismic events in real time provides the ability tounderstand where the fracture is being positioned in the formation 30and how the fracture is growing in all directions (x,y,z) relative tothe pumping rates, the particular fracturing fluid and any number ofother parameters with respect to the fracturing operation. The abilityto rapidly optimize the design and placement of fractures provides theability to build databases related thereto which may be of great use tothe industry in improving fracture operations. Further, such informationpermits data, such as where the fluid has gone, to be provided for thepublic record regarding each stage of the fracturing operation andfracture location and extent.

Particularly advantageous, when monitoring in real time, is the abilityto determine whether a fracture has broken out of a zone or isimminently in danger of breaking out of a zone so that pumping can bestopped. This is of great interest, for many reasons, where the fractureis breaking towards a water zone.

Growth of a fracture, vertically or horizontally at a certain rate, maybe related to the pumping rate and concentration of the fracturingfluid. Over time and using the data obtained by embodiments disclosedherein, one could design a fracturing operation to achieve maximumvertical height without breaking out of the zone and maximum, economichorizontal displacement leading to horizontal well spacing optimizationand field development optimization.

In the case of openhole wellbores 12, embodiments using microseismicmonitoring as described herein are less susceptible to noise as there isless transmission of noise in the wellbore 16 without the casing orliner 18.

Additional Embodiments

Embodiments of the BHA's described above comprise substantiallyelectrically-actuated tools. As one of skill in the art will appreciatehowever, embodiments are possible which utilize a combination ofmechanically-actuated and electrically-actuated tools.

In an embodiment using electrically-enabled CT, mechanically-actuatedfracturing tools, such as taught in Applicant's co-pending U.S.application Ser. No. 13/773,455 incorporated herein in its entirety, orother, conventional mechanically-actuated fracturing tools, may becombined with electrically-actuated perforating apparatus, as taughtherein.

In yet another embodiment, using electrically-enabled and/or fiberoptic-enabled CT, mechanically-actuated fracturing tools and perforatingapparatus can be combined with microseismic monitoring apparatus astaught herein and which is operable in real time having datatransmission to surface through the CT.

Embodiments utilizing electrically-enabled and/or fiber optic-enabledCT, mechanically-actuated fracturing tools and perforating apparatuscombined with microseismic monitoring operated in a memory mode can usesignals transmitted to surface through the fiber optics for minimizingnoise in the data which is later retrieved from the BHA.

Diagnostic Testing

A minifrac test is an injection falloff diagnostic test that isperformed for establishing formation pressure and permeability prior topumping the main fracture stimulation. A short fracture is createdduring the injection of fluid, without proppant, and the fractureclosure is observed during the ensuing falloff period. The minifrac isused to establish design parameters for the main fracture stimulationand is typically performed immediately prior thereto.

Using a BHA 10, according to an embodiment having the first and secondvariable diameter packers 22 f,22 s disclosed herein, the minifrac ispumped, and following pumping the minifrac, the first packer 22 f isunset from the sealing position and the CT is unloaded with nitrogen.Thereafter, the first packer 22 f is reset to the sealing position andadditional testing can be performed, such as the DFIT or NFIT test tomonitor the fracture closure pressure, production, or the like.

Rock Stress Relief

Where adjacent zones in the formation 30 are to be fractured, there isconcern that reductions in rock stress about a previously fractured zonemight cause a fracture formed in the adjacent zone to break through tothe previous fracture.

Having reference again to FIG. 6, and to minimize reductions in rockstress about the previous fractures, the valve 50 is actuated to permitfluid to be delivered through the bore 38 of the electrically-enabled CT12 to the fluid crossover port 60 below the first packer 22 f. The fluidF exits the fluid crossover port 60 to the annulus 34 below the firstpacker 22 f and to the previously perforated and fractured zonestherebelow to enter the perforations P and fractures to increase therock stress about the previous fractures. In this case, while fluid F isdelivered through the fluid crossover port 60, the fracturing fluid F issimultaneously delivered to the annulus 34 above the first packer 22 fat suitable fracturing pressures for exiting the perforations P andfracturing the newly perforated, adjacent zone. In embodiments, cleanfluid Fc is delivered through the electrically-enabled CT 12 to theannulus 34 below the first packer 22 f to elevate the pressure P2therein to be equal to or greater than the pressure P1 above the firstpacker 22 f.

The ability to provide fluid F below the first packer 22 f through theelectrically-enabled CT 12 using the valve 50 provides a relativelysimple means to avoid the problems related to reduced rock stress andwhich largely avoids the need for the complex, carefully orchestrated,simultaneous fracturing operations at multiple sites in side-by-sidewellbores in a formation required according to prior art “zipper”fracturing techniques.

The embodiments in which an exclusive property or privilege is claimedare defined as follows:
 1. A system for completing and treating awellbore, the system comprising: electrically-enabled coiled tubing (CT)having a CT bore formed therethrough; and a bottom hole assembly (BHA)having, from a proximal end to a distal end, at least a treatment headand a packer, wherein the treatment head comprises fracturing ports toan annulus between the BHA and wellbore; the packer beingelectrically-actuated and comprising a packer element; and an electricpacker drive electrically connected to the CT for electrically actuatingthe packer element between a first sealing diameter for sealing in thewellbore and at least a second running diameter, the running diameterbeing sized to be movable within the wellbore and acting as a piston forpumping the BHA and CT downhole within the wellbore.
 2. The system ofclaim 1, wherein the packer further comprises slips.
 3. The system ofclaim 1 wherein the CT and BHA form an injection string, the systemfurther comprising: a strain sensor along the injection string uphole ofthe packer, the strain sensor electrically connected to the CT forproviding signals indicative of axial loading in the string at aboutBHA, a controller for receiving axial loading signals and for managing arate of injection of the CT and a rate of pumping of the BHA formanaging the axial loading.
 4. The system of claim 1 wherein thewellbore is cased or lined, further comprising: a casing collar locater(CCL) for engaging a casing collar for positioning the BHA in thewellbore; and a perforating apparatus for perforating the casing orliner.
 5. The system of claim 2 wherein the perforating apparatus is anelectrically-actuated, selectively-fired perforating gun furthercomprising a plurality of perforating segments, the system furthercomprising: a top connector sub at the perforating apparatus forselectively triggering each of the perforating segments; and a firingpanel at surface, the firing panel being electrically connected to theCT and to the top connector sub.
 6. The system of claim 1, wherein theBHA comprises a throughbore and the treatment head further comprises avalve for alternately directing fluid to either the fracturing ports orthe throughbore, the valve being electrically actuated, the BHA furthercomprising an electric valve drive electrically connected to the CT foractuating the valve.
 7. The system of claim 6 wherein the valve furtherdirects fluid from the throughbore to a bore of the BHA below thepacker.
 8. The system of claim 1 wherein the electric drive furtheractuates the packer to a minimum packer diameter for tripping out of thewellbore.
 9. The system of claim 2 wherein the CCL is electronic andelectrically connected to the CT through an electronics sub in the BHA.10. The system of claim 1 wherein the BHA further comprises: one or moreseismic sensors for monitoring microseismic signals during fracturing.11. The system of claim 10 wherein the one or more sensors are two ormore axially spaced, 3-component geophones.
 12. The system of claim 10wherein the one or more seismic sensors are positioned downhole of thetreatment head for isolating the one or more sensors therefrom.
 13. Thesystem of claim 10 further comprising sensors for determiningorientation of the one or more seismic sensors relative to surface. 14.The system of claim 10 wherein microseismic data from the one or moreseismic sensors are electrically connected to the CT for communicationof microseismic data to surface in real time.
 15. The system of claim 10further comprising a downhole processor with memory for storingmicroseismic data from the one or more seismic sensors for retrievaltherefrom at surface.
 16. The system of claim 1 wherein the CT furthercomprises fiber optics extending uphole from the BHA for optical signalcommunication between the BHA and surface.
 17. The system of claim 10wherein the CT further comprises fiber optics extending uphole from theBHA, the fiber optics forming a linear array of distributed fiber opticsensors for along the wellbore for detecting compressional waves frombackground noise and transmitting the signals therefrom to surface, forremoval of the noise from the microseismic signals.
 18. The system ofclaim 10 wherein the two or more axially spaced, 3-component geophonesfurther comprise arms electrically connected to the CT and actuablebetween an extended position for coupling the geophones to the casing orwellbore for seismic coupling thereto; and a retracted position fordecoupling therefrom.
 19. The system of claim 1 wherein the BHA furthercomprises: an electronics sub; and pressure sensors electricallyconnected to the electronics sub for monitoring pressure above and belowthe at least one packer, the electronics sub electrically connected tothe CT for communications to surface.
 20. The system of claim 19 whereinthe BHA further comprises: temperature and vibration sensorselectrically connected to the electronics sub.
 21. The system of claim 1wherein the packer is a first packer and the electric drive is a firstelectric drive, the system further comprising: a second packer, upholeof the treatment head, the second packer having a packer element andbeing electrically-actuated; and a second electric packer driveelectrically connected to the CT for electrically actuating the secondpacker element between the sealing position and at least a secondrunning diameter, the running diameter of the second packer elementbeing sized to be movable within the wellbore and acting as a piston forpumping the BHA and CT downhole within the wellbore.
 22. The system ofclaim 21 wherein: the first packer element is electrically-actuated to aminimum diameter; and the second packer element is electrically-actuatedfor pumping the BHA and CT downhole within the wellbore.
 23. The systemof claim 21, wherein the BHA is secured in the wellbore as a result ofpressure balancing across the first and second packers.
 24. The systemof claim 21 wherein the BHA further comprises: an electronics sub; andpressure sensors electrically connected to the electronics sub formonitoring pressure above and below each of the first and secondpackers.
 25. The system of claim 21, wherein the BHA comprises athroughbore and the treatment head further comprises a valve foralternately directing fluid to either the fracturing ports or thethroughbore, the valve being electrically actuated, the BHA furthercomprising an electric valve drive electrically connected to the CT foractuating the valve.
 26. The system of claim 25 wherein the valvefurther directs fluid from the throughbore to a bore of the BHA belowthe packer.
 27. The system of claim 21 wherein the BHA furthercomprises: one or more seismic sensors for monitoring microseismicsignals during fracturing.
 28. The system of claim 27 wherein the one ormore sensors are two or more axially spaced, 3-component geophones. 29.The system of claim 27 wherein the one or more seismic sensors arepositioned downhole of the treatment head for isolating the one or moresensors therefrom.
 30. The system of claim 27 further comprising sensorsfor determining orientation of the one or more seismic sensors relativeto surface.
 31. The system of claim 27 wherein microseismic data fromthe one or more seismic sensors are electrically connected to the CT forcommunication of microseismic data to surface in real time.
 32. Thesystem of claim 27 further comprising a downhole processor with memoryfor storing microseismic data from the one or more seismic sensors forretrieval therefrom at surface.
 33. The system of claim 21 wherein theCT further comprises fiber optics extending uphole from the BHA foroptical signal communication between the BHA and surface.
 34. The systemof claim 27 wherein the CT further comprises fiber optics extendinguphole from the BHA, the fiber optics forming a linear array ofdistributed fiber optic sensors for along the wellbore for detectingcompressional waves from background noise and transmitting the signalstherefrom to surface, for removal of the noise from the microseismicsignals.
 35. The system of claim 21 wherein the wellbore is cased orlined and having fluid communication with the wellbore, furthercomprising a casing collar locater (CCL) for engaging a casing collarfor positioning the BHA in the wellbore.
 36. The system of claim 35further comprising perforating apparatus for perforating the casing orliner.
 37. The system of claim 36 wherein the perforating apparatus isan electrically-actuated, selectively-fired perforating gun furthercomprising a plurality of perforating segments, the system furthercomprising: a top connector sub at the perforating apparatus forselectively triggering each of the perforating segments; and a firingpanel at surface, the firing panel being electrically connected to theCT and to the top connector sub.
 38. A method of deploying andpositioning a BHA in a wellbore comprising: deploying the BHA inelectrically-enabled coiled tubing, the BHA comprising at least onepacker having an electrically-actuable packer element electricallyactuating the packer element to expand to a running diameter being lessthan a diameter of the wellbore; pumping fluid through an annulusbetween the wellbore and the BHA, the packer element acting as ahydraulic piston for pumping the packer, the BHA and the CT downhole inthe wellbore; and electrically actuating the packer element to expand toa sealing diameter for sealing the annulus.
 39. The method of claim 38wherein the step of deploying the BHA, when encountering debris in thewellbore, further comprises: electrically actuating the packer elementto reduce to a minimum diameter less than the running diameter, topermit the debris to pass the packer and BHA.
 40. A method for treatingone or more zones of interest in a formation intersected by a casedwellbore comprising: providing a bottom-hole assembly (BHA) andelectrically-enabled coiled tubing (CT), the CT having a CT boretherethrough, the BHA having, from a proximal end to a distal end, atleast a treatment head, at least one packer and a perforating apparatus,preparing BHA packer for running into the wellbore by electricallyactuating a packer element to a running diameter pumping fluid throughan annulus between the BHA and the casing to act at the packer forpumping the BHA and CT downhole and positioning the perforationapparatus adjacent a lowermost zone of interest; actuating theperforating apparatus to perforate the casing at the zone of interest;pumping fluid through the annulus for pumping the BHA and CT downhole soas to position the packer below the perforations; electrically-actuatingthe packer element to a sealing position to seal the annulus and anchorthe BHA in the cased wellbore; pumping a treatment fluid through theannulus, through the coiled tubing and through the treatment head, orboth, for delivery to the perforations and the zone of interest;stopping the pumping of the treatment fluid; equalizing pressure acrossthe packer; electrically-actuating the packer element from the sealingdiameter to the running diameter; pulling the CT and BHA uphole forrepositioning the perforating apparatus adjacent another uphole zone ofinterest; and without removing the BHA from the wellbore, repeating thesteps for the at least the another uphole zone of interest.
 41. Themethod of claim 40 wherein the pumping of the treatment fluid throughthe annulus, or through the CT for pumping through the treatment head,or both, further comprises electrically actuating a valve at thetreatment head for alternately directing fluid from the CT bore to theannulus.
 42. The method of claim 40 wherein the perforating apparatus isan electrically-actuated perforating gun comprising a plurality ofperforating segments electrically connected to the CT and to a firingpanel at surface, the step of actuating the perforating apparatuscomprises: electronically actuating, from the firing panel, a select oneor more of the perforating segments.
 43. The method of claim 40 whereinthe BHA further comprises a casing collar locator (CCL), the step ofpositioning the BHA further comprising: engaging the CCL with a casingcollar adjacent the zone of interest for positioning the BHA.
 44. Themethod of claim 43 wherein the casing collar locator (CCL) iselectrically connected to the CT, the step of positioning the furthercomprises: electrically sensing a casing collar or perforations in thewellbore at the zone of interest with the CCL for positioning the BHA.45. The method of claim 40 wherein the BHA further comprises pressuresensors electrically connected to the CT above and below the packer; andafter the step of electrically actuating the packer element to reducefrom the sealing diameter to the running diameter for relocating the BHAin the wellbore or tripping the BHA out of the wellbore, the methodfurther comprising: monitoring the pressure data from the one or morepressure sensors at surface for determining when the pressure above thepacker and below the packer are balanced.
 46. The method of claim 40wherein the cased wellbore has a plurality of spaced apart ported sleevesubs incorporated therein, sleeves in the ported sleeve subs beingactuable between a closed position for blocking one or more portsthrough the casing and an open position for opening the one or moreports for treating the formation therethrough, the method comprising:engaging the sleeve at the zone of interest with the BHA andelectrically-actuating the BHA to move the sleeve to the open position.47. The method of claim 46, after the step of pumping the treatmentfluid to the perforations, further comprises: engaging the sleeve withthe BHA and electrically-actuating the BHA to move the sleeve to theclosed position.
 48. The method of claim 40, wherein the BHA furthercomprises one or more 3-component sensors, the method comprising:monitoring microseismic events in the wellbore and outside the wellboreusing the one or more 3-component sensors for collecting microseismicdata from x, y and z.
 49. The method of claim 48 wherein the one or more3-component sensors are electrically connected to the CT, the methodcomprising: transmitting the x, y and z data from the two or more3-component sensors to surface through the electrically-enabled CT, inreal time.
 50. The method of claim 48, wherein one or more 3-componentsensors comprise storage memory and a battery, the method furthercomprising: storing the x, y and z data from the two or more 3-componentsensors in the memory retrieving the storage memory to surface with theBHA.
 51. The method of claim 40 wherein the packer is a downhole firstpacker and the BHA further comprises an uphole second packer having apacker element independently controllable from the first packer, thesecond packer being spaced uphole of the fracturing ports andelectrically connected to the CT; the step of deploying the BHA furthercomprising: electrically actuating the packer element of one or both ofthe first and second packers to expand the diameter to the runningdiameter; pumping fluid through the annulus for pumping the one or bothof the first and second packers and the BHA downhole; and prior topumping treatment fluid through the annulus, actuating the packerelement of the second packer to retract to a minimum packer diameter.52. The method of claim 51 wherein one or more perforations hassanded-off, the method further comprising: releasing the second packerby electrically actuating the packer elements of the second packer toreduce the diameter to about a minimum disameter; pumping a fluidthrough the CT bore for circulating the fluid to surface through theannulus for cleaning sand from the perforations; and when cleanedelectrically-actuating the second packer to re-expand the packer elementto the sealing diameter for re-sealing the annulus between the BHA andthe wellbore uphole of the perforations; and pumping the treatment fluidto the perforations and into the formation.
 53. The method of claim 40for use in wellbores having existing perforations or open ports therein,wherein the packer is a first packer and the BHA further comprises asecond packer having a packer element independently controllable fromthe first packer, the second packer being positioned uphole of thefracturing ports, further comprising: positioning the BHA having thesecond packer uphole of the existing perforations or open ports and thefirst packer downhole thereof; independently electrically-actuating thepacker element of each of the first packer and the second packer to thesealing diameter for sealing the annulus between the BHA and thewellbore above and below the existing perforations; pumping thetreatment fluid through the CT bore to the fracturing ports for deliveryto the zone of interest; stopping the pumping of the treatment fluid;and independently electrically-actuating the packer element of the firstpacker and the packer element of the second packer to reduce thediameter to the running diameter.
 54. A method for treating multipleintervals of one or more formations intersected by a cased wellborehaving existing perforations or open ports therein, at one or more zonesof interest, the method comprising: injecting a bottom-hole assembly(BHA) into the wellbore using electrically-enabled coiled tubing (CT),the CT having a CT bore therethrough, the BHA having, from a proximalend to a distal end, at least a treatment head, a first packer downholeof the treatment head and a second packer uphole of the treatment headwherein the treatment head comprises fracturing ports, a throughbore anda valve for alternately directing fluid between the fracturing ports andthe throughbore; and each of the first and second packers comprises apacker element and an electric packer drive electrically connected tothe coiled tubing for independently actuating the packer element of thefirst and second packer between a sealing diameter for sealing in thewellbore and a running diameter for acting as a piston to aid in movingthe BHA and CT downhole within the wellbore. electrically-actuating thepacker element of one or both of the first and second packers to therunning position; pumping fluid through an annulus between the BHA andthe casing to act at the packer in the running diameter for positioningthe BHA having the first packer below the existing perforations or openports and the second packer thereabove for straddling the perforationsor open ports; electrically-actuating the packer element of the firstpacker and the second packer to the sealing position to seal in thewellbore; anchoring the BHA in the cased wellbore; pumping a treatmentfluid through the CT bore to the fracturing ports for delivery to theperforations or open ports and to the zone of interest; stopping thepumping of the treatment fluid; equalizing pressures above, between andbelow the first and second packers; electrically actuating the packerelements of the first and second packer element to reduce from thesealing diameter to at least the running diameter; repositioning the BHAso as to straddle existing perforations or open ports between the firstand second packers at another zone of interest; and without removing theBHA from the wellbore, repeating the steps for the at least the anotherzone of interest.
 55. The method of claim 54 wherein the wellborefurther comprises one or more zones of interest without existingperforations or opened ports therein, the BHA further comprising aperforating apparatus downhole of the first packer, the method furthercomprising: positioning the BHA having the perforating apparatusadjacent one of the one or more zones without existing perforations oropened ports; actuating the perforating apparatus to form newperforations at the zone of interest without existing perforations;repositioning the BHA having the first packer downhole of the newperforations and the second packer thereabove; independentlyelectrically-actuating the packer element of the first and second packerto expand to the sealing diameter for sealing the annulus between theBHA and the wellbore; pumping the treatment fluid through through the CTbore to the fracturing ports for delivery to the perforations and to theformation therethrough; stopping the pumping of treatment fluid;equalizing pressures above, between and below the first and secondpackers; independently electrically actuating the packer element of eachof the first and second variable diameter packers to reduce to at leastthe running diameter; and repositioning the BHA adjacent another zone ofinterest without removing the BHA from the wellbore.
 56. The method ofclaim 54 wherein the perforating apparatus is an electrically-actuatedperforating gun comprising a plurality of perforating segmentselectrically connected to the CT and to a firing panel at surface, thestep of actuating the perforating apparatus comprises: electronicallyactuating, from the firing panel, a select one or more of theperforating segments.
 57. A method for treating multiple intervals ofone or more formations intersected by a cased wellbore in a single tripwherein one or more perforations has sanded-off, the method comprising:injecting a bottom-hole assembly (BHA) into the wellbore usingelectrically-enabled coiled tubing (CT), the CT having a CT boretherethrough, the BHA having, from a proximal end to a distal end, atleast a treatment head, a first packer downhole of the treatment headand a second packer uphole of the treatment head wherein the treatmenthead comprises fracturing ports, a throughbore and a valve foralternately directing fluid between the fracturing ports and thethroughbore; and the first and second packers comprises a packer elementand an electric packer drive electrically connected to the coiled tubingfor independently actuating the packer element of the first and secondpacker between a sealing diameter for sealing in the wellbore and arunning diameter for acting as a piston to aid in moving the BHA and CTdownhole within the wellbore. positioning the BHA having the secondpacker uphole of perforations or open ports at a first zone of interestand the first variable diameter packer downhole thereof;electrically-actuating packer elements of the second packer to expandthe variable diameter to a sealing diameter for sealing an annulusbetween the BHA and the wellbore; electrically-actuating packer elementsof the second packer to expand the variable diameter to a sealingdiameter for sealing an annulus between the BHA and the wellboretherebelow; pumping a treatment fluid to the perforations and into theformation, through the coiled tubing to the fracturing ports and to theperforations or opened ports; and wherein when the perforations or openports sands off releasing the second variable diameter packer byelectrically actuating the packer elements of the second packer toreduce the diameter of the second packer to a minimum packer diameter;continuing pumping a fluid for circulating the fluid to surface throughthe annulus for cleaning sand from the perforations for clearing thesand-off and thereafter electrically-actuating the second packer tore-expand the packer elements to the sealing diameter for re-sealing theannulus between the BHA and the wellbore uphole of the perforations; andpumping the treatment fluid to the perforations and into the formation,through the coiled tubing to the fracturing ports and to theperforations or opened ports.
 58. A method for reducing rock stressduring treatment of a formation comprising: deploying a BHA in awellbore; positioning fracturing ports in the BHA adjacent a first zoneof interest; setting a packer in the BHA below the fracturing ports toisolate an annulus between the BHA and the wellbore; deliveringtreatment fluid to the fracturing ports for fracturing the formation atthe zone of interest; releasing the packer; repositioning the BHA forpositioning fracturing ports in the BHA at a subsequent zone of interestadjacent the first zone of interest; setting the packer to isolate theannulus; and while delivering treatment fluid to the fracturing portsfor fracturing the formation at the subsequent adjacent zone ofinterest; flowing fluid through the BHA to below the packer for deliveryto the first zone of interest for reducing rock stress in the first zoneof interest during fracturing of the adjacent zone of interest.
 59. Themethod of claim 58 further comprising: repeating the steps ofrepositioning, setting and flowing fluid below the packer to the zonestherebelow while delivering treatment fluid to another subsequent zonesof interest.
 60. A method for reducing rock stress during treatment of aformation comprising: injecting a bottom-hole assembly (BHA) into thewellbore using electrically-enabled coiled tubing (CT), the CT having aCT bore therethrough, the BHA having, the BHA having, from a proximalend to a distal end, at least a treatment head and a packer, wherein thetreatment head comprises fracturing ports, a throughbore and a valve foralternately directing fluid between the fracturing ports and thethroughbore; and the packer comprises a packer element and an electricpacker drive electrically connected to the coiled tubing for actuatingthe packer element between a sealing diameter for sealing in thewellbore and a running diameter for acting as a piston to aid in movingthe BHA and CT downhole within the wellbore; electrically-actuating thepacker element to the running position; pumping fluid through an annulusbetween the BHA and the casing to act at the packer for positioning theBHA so as to position the packer below perforations in the wellbore;electrically-actuating the packer element to the sealing position toseal in the wellbore; pumping a treatment fluid through the annulus,through the CT, or both, for delivery to the perforations and the zoneof interest; stopping the pumping of the treatment fluid; electricallyactuating the packer element to reduce from the sealing diameter to therunning diameter; repositioning the BHA at a subsequent adjacent zone ofinterest; and while delivering treatment fluid to the fracturing portsfor fracturing the formation at the subsequent adjacent zone ofinterest; actuating the valve for delivery fluid to the fracturing portsand to the throughbore for delivering fluid below the packer; andflowing fluid below the packer for delivery to the first zone ofinterest for reducing rock stress in the first zone of interest duringfracturing of the subsequent adjacent zone of interest.
 61. The methodof claim 60 further comprising: repeating the steps of repositioning,setting and flowing fluid below the packer to the zones therebelow whiledelivering treatment fluid to another subsequent zones of interest.